Viscous oil recovery using electric heating and solvent injection

ABSTRACT

To recover in situ viscous oil from an underground reservoir, electricity is conducted through the underground reservoir by at least two electrodes in an amount that would, in the absence of solvent injection, cause water in the reservoir to vaporize adjacent to the electrodes, and injecting solvent into the reservoir to mitigate water vaporization adjacent to the electrodes by vaporizing solvent in this region. Oil and solvent are produced through one or more production wells.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims priority from Canadian Patent Application number2,707,283 filed Jun. 11, 2010, entitled Viscous Oil Recovery UsingElectric Heating and Solvent Injection, the entirety of which isincorporated by reference herein.

FIELD OF THE INVENTION

The present invention relates generally to in situ recovery ofhydrocarbons. More particularly, the present invention relates to theuse of electric heating to recover in situ hydrocarbons includingviscous oil such as bitumen.

BACKGROUND OF THE INVENTION

Recovering viscous oil from a subterranean reservoir in an economicmanner typically requires reducing the in situ viscosity of the oil.Most commonly, this is accomplished by steam injection. Steamflooding(see for example U.S. Pat. No. 3,705,625 (Whitten)), cyclic steamstimulation (CSS) (see, for example, U.S. Pat. No. 4,280,559 (Best)),and steam assisted gravity drainage (SAGD) (see for example U.S. Pat.No. 4,344,485) are well-known methods that employ steam injection toreduce in situ oil viscosity.

Steam injection, however, is not always an appealing method. Steamgeneration requires large upfront capital expenditures for waterhandling and clean-up facilities. Additionally, steam is costly todistribute over a large field due to thermal losses in pipes.Alternatives to steam injection include electrical heating and solventaddition. Each is useful by itself as a way to aid the recovery ofviscous oil from subterranean reservoirs.

Certain prior disclosures exist describing methods using both electricalheating and solvent addition to aid the recovery of viscous oil fromsubterranean formations.

U.S. Pat. No. 4,450,909 discloses a method for opening a fluid.communication channel between injection and production wells in apreviously unheated heavy oil reservoir wherein the oil is not amenableto being produced by a drive fluid, which consists essentially ofinjecting a cold solvent for the heavy oil into the unheated reservoir;and while such solvent is moving through the unheated reservoir,simultaneously passing electric current between a positive electrodepositioned in the injection well and a negative electrode positioned inthe production well to reduce the injection pressure required.

U.S. Patent Publication No. 2009/0090509 discusses using a solvatingfluid to aid the recovery of the heavy oil from tar sands which isheated using electrical resistive heat sources. The process involvesusing solvent as a secondary process to improve the recovery from aneighboring area that received residual heat from a first area or toimprove the recovery of remaining hydrocarbons after an area has beenlargely produced by heating and gravity drainage.

U.S. Pat. No. 4,412,585 discloses a method comprising a pair ofinjection and production wells for recovering heavy hydrocarbons whereelectrodes are formed by inserting a heating device in each borehole andheating the surrounding formation to a temperature at which thehydrocarbon-containing material undergoes thermal cracking, resulting ina coke-like residue surrounding the heater. This conductive andpermeable material serves as an electrode, for each well, by which theformation is heated. The heavy hydrocarbon material, such as bitumenfound in tar sands, becomes mobile and can be recovered. Additionally, ahydrocarbon solvent, such as a C₆-C₁₄ liquid, can be used to displacethe oily bitumen from the formation.

U.S. Pat. No. 4,085,803 discloses a method for recovering hydrocarbonsfrom a subterranean formation where a heated fluid, such as steam orsolvent, is injected into the formation by means of a perforated conduitwhich is positioned substantially horizontally through the formation toheat hydrocarbons within the formation. After a suitable heating period,injection of heat is terminated to permit fluids including formationhydrocarbons to drain from the formation into the conduit. The drainedfluids within the conduit are then heated to a temperature such that atleast a portion of the drained fluids are vaporized. These vaporizedfluids pass from the perforated conduit and into the formation tofurther heat formation hydrocarbons. Subsequently, formation fluids ofreduced viscosity are recovered from the formation through theperforated conduit.

U.S. Pat. No. 5,167,280 discloses a solvent stimulation process where aviscosity-reducing agent is circulated through a horizontal well via aproduction string. This agent exits the production string and enters anannulus formed by said string and a liner. This agent diffuses into thereservoir at a pressure below the reservoir pressure. As this agentdiffuses through the reservoir under the influence of a concentrationgradient, it reduces the oil's viscosity and makes it mobile.Simultaneously, oil of reduced viscosity migrates into the well under apressure drawdown influence.

USSR Patent Document No. 1,723,314 discloses a method for the recoveryof viscous or bituminous crude oil where solvent, or a mixture ofsolvents, is pumped into a producing seam through the injection hole. Atthe same time, the bottom-hole zone is heated by a high frequencyelectromagnetic field until the viscosity of the hydrocarbons increasessufficiently and corresponds with the viscosity of the solvent, i.e., itis of the same order of magnitude. Then, the electromagnetic action isstopped, and is recommenced again when the bottom-hole temperature fallsbelow the seam temperature.

T. N. Nasr and O. R. Ayodele (SPE Paper 101717, “New HybridSteam-Solvent Process for the Recovery of Heavy Oil and Bitumen”, 2008)describe a modification of the well-known steam-assisted gravitydrainage (SAGD) method where, by introducing heat through electricalheating or the injection of a small amount of steam, the heat may serveto establish communication between an injector and producer well andspeed diffusion of an injected solvent into the oil interface at theedge of the vapor chamber. As diluted oil moves towards the producerwell, vaporized solvent is driven out of the oil by heat and the solventreturns to the vapor chamber where it mobilizes more oil.

U.S. Pat. No. 5,400,430 discloses a method of stimulating an injectionwell comprising placing an electric heater within the well, at or nearthe bottom, adjacent to the area to be treated. Solvent is flowed pastthe energized heater to heat the solvent and then heated solvent flowsinto the treatment area to contact and remove solid wax deposits locatedin the treatment area and then injecting waterflood water into theinjection well. This patent focuses on removing near-wellbore waxyblockages and does not involve conducting electricity through theformation.

U.S. Pat. No. 5,167,280 discloses a solvent stimulation process where asolvent is circulated through a horizontal well via a production string.The solvent diffuses through the reservoir under the influence of aconcentration gradient and reduces the oil's viscosity and makes itmobile. In some embodiments, the reservoir is thermally stimulated by anelectrical induction or electromagnetic heating process so as to heatthe stimulated zone containing the horizontal wellbore. This patent doesnot envision pressure-driven flow of solvent through the reservoir noruse of resistive heating of the reservoir.

Variations on electrothermal heating of viscous oil formations aredescribed in Canadian Patent Nos. 2,043,092, 2,120,851, U.S. Pat. Nos.849,524, 3,782,465, 3,946,809, 3,948,319, 3,958,636, 4,010,799,4,228,853, 4,489,782, 4,679,626, and U.S. Application Publication Nos.2008/0236831, and 2008/0277113.

There are three general classes of electric heating: electricalresistive heating of a subsurface heating element (e.g., a wellboreelement or an electrically conductive propped fracture), radio frequencyheating of the reservoir by high-frequency alternating electromagneticwaves propagating through the formation, and electrothermal heating ofthe reservoir itself by ohmic electrical conduction through thereservoir.

In certain cases, electrothermal heating may be the preferred heatingapproach. Energy may be distributed to a reservoir much faster byelectrothermal heating than by electrical resistive heating of a heatingelement. Thermal conduction of heat away from a heating element istypically fairly slow, whereas electrical conduction through thereservoir is essentially instantaneous. Radio frequency heating may alsorapidly send heat into a reservoir. However, radio frequency heating issignificantly more complex than ohmic heating due to the need forhigh-frequency alternating current to be generated and sent down intothe subsurface.

Electrical conduction through a reservoir necessary for electrothermalheating occurs due to electricity flowing through a conductive brine inthe reservoir. However, conduction ceases if the brine sufficientlyheats that it boils away. This is particularly an issue near electrodeswhere, due to geometric factors, the electrical current is concentratedand thus maximum heating may occur. This behavior generally means thatthe heating of the bulk reservoir has to be kept fairly modest so as toprevent overheating near the electrodes. Being limited to modesttemperatures may result in insufficient viscosity reduction of the oiland thus cause unacceptably slow oil production rates.

One method of moderating temperatures near an electrode is to injectwater or brine through or near the electrode. The injected waterconvects heat away and prevents the region adjacent to an electrode fromdrying out and thus losing electrical conductivity. However, brineinjection near an electrode may be problematic since the heating maycause salts to precipitate and foul the injection well and thenear-wellbore region. Thus, there exists a need for improved methods formoderating temperatures near an electrode to maintain a desiredelectrical conductivity for improved hydrocarbon recovery. Moreover,there exists a need for improved hydrocarbon methods whichsynergistically combine in situ electrical heating with solvent-aidedrecovery methods.

SUMMARY OF THE INVENTION

According to an aspect of the present invention, there is provided amethod of recovering hydrocarbons from a subterranean reservoir by thesynergistic use of electrothermal heating and solvent injection. Themethod requires that a conductive brine exist between electrodesdisposed within the reservoir. The conductive brine may be naturallyoccurring or may comprise injected brine. The conductivity of the brineshould be such that fluid-filled reservoir rock has a low electricalresistivity, for example less than 100 ohm-meters, 10 ohm-meters, oreven 1 ohm-meter. The solvent is used to limit vaporization of water inthe brine adjacent to one or more of the electrodes so as to maintaingood electrical conductivity between electrodes. Sufficient electricityis supplied that would, in the absence of solvent injection, cause waterto vaporize within the reservoir adjacent to the one or more electrodes.The electro-thermal heating reduces the viscosity of the oil. Sufficientsolvent is injected to keep the reservoir adjacent to the one or moreelectrodes below the boiling point temperature of water at reservoirpressure conditions. Finally, oil and solvent are produced through oneor more production wells.

According to another aspect of the present invention, there is provideda method of recovering hydrocarbons from an underground reservoirincluding conducting electricity at least partially through a conductivebrine within the reservoir between two or more electrodes disposed inthe reservoir. Solvent is injected into the reservoir at least partiallyin a liquid phase. In one embodiment, the solvent is a fluid which is atleast modestly soluble in the oil at reservoir conditions, e.g., havinga solubility limit of at least 5%, or at least 20%, or at least 50% bymass in the oil within the reservoir. The solvent may have a bubblepoint temperature between 10° C. and 100° C. at a pressure of 1atmosphere, e.g., the bubble point at a pressure of 1 atmosphere forn-pentane is 36° C., for n-hexane is 69° C., and for n-heptane is 98° C.Alternatively, or in addition, solvents may include components otherthan linear alkanes, e.g., cycloalkanes, aromatics, ketones, oralcohols. A portion of the reservoir is heated through the conduction ofelectricity to vaporize at least a portion of the injected solvent. Thehydrocarbons are produced through one or more wells.

According to another aspect of the present invention, there is provideda method of recovering hydrocarbons from an underground reservoir, themethod comprising: conducting electricity at least partially through aconductive brine within the reservoir between two or more electrodesdisposed in the reservoir; injecting solvent into the reservoir at leastpartially in a liquid phase and where the solvent has a bubble pointtemperature between 10° C. and 100° C. at a pressure of 1 atmosphere;heating a portion of the reservoir through the conduction of electricityto vaporize at least a portion of the injected solvent; and producinghydrocarbons through one or more wells. Within this aspect, thefollowing features may be present. Sufficient solvent may injected intothe reservoir and proximate to one or more of the two or more electrodesto maintain the portion of the reservoir at a temperature below theboiling point temperature of water at reservoir pressure conditions. Thehydrocarbons may be a viscous oil having an in situ viscosity greaterthan 10 cP at initial reservoir conditions. The portion of the reservoirmay be adjacent to at least one of the two or more electrodes. Themethod may further comprise injecting a conductive brine into thereservoir to further control reservoir in situ temperature or tomaintain or achieve in situ conductivity. The solvent may comprisepropane, butane, pentane, hexane, or heptane, or a combination thereof.The method may further comprise heating the solvent above ground priorto injection. The method may further comprise heating the solventbeneath ground prior to injection. The solvent heating may be effectedby a subsurface electric heating element. The solvent may be at leastpartially produced as a vapor. One or more wells used for solventinjection may also be used as, or may house, one or more of the two ormore electrodes. One or more of the one or more wells used forproduction may also be used as, or house, one or more of the two or moreelectrodes. The solvent may be injected through at least two injectionwells which act as, or house, the two or more electrodes, respectively.The solvent may have a bubble point temperature between 35° C. and 99°C. at a pressure of 1 atmosphere. The solvent may have a solubilitylimit at reservoir conditions of at least 5% by mass in thehydrocarbons. The solvent may have a solubility limit at reservoirconditions of at least 20% by mass in the hydrocarbons. The solvent mayhave a solubility limit at reservoir conditions of at least 50% by massin the hydrocarbons. At least 25 mass % of the solvent may enter thereservoir as a liquid. At least 50 mass % of the solvent may enter thereservoir as a liquid. The solvent may comprise greater than 50 mass %of components comprising propane, butane, or pentane. The solvent maycomprise greater than 50 mass % propane. The solvent may comprisegreater than 70 mass % propane. Cycles of solvent injection and solventand hydrocarbon production may occur through the one or more wells andthe one or more wells may also act as or house one or more of the two ormore electrodes.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic of viscous oil recovery using electric heating andsolvent injection, in accordance with a disclosed embodiment; and

FIG. 2 is a schematic of viscous oil recovery using electric resistiveheating and solvent injection, in accordance with a disclosedembodiment.

DETAILED DESCRIPTION

The term “viscous oil” as used herein means a hydrocarbon, or mixture ofhydrocarbons, that occurs naturally and that has a viscosity of at least10 cP (centipoise) at initial reservoir conditions. Viscous oil includesoils generally defined as “heavy oil” or “bitumen”. Bitumen isclassified as an extra heavy oil, with an API gravity of about 10° orless, referring to its gravity as measured in degrees on the AmericanPetroleum Institute (API) Scale. Heavy oil has an API gravity in therange of about 22.3° to about 10° . The terms viscous oil, heavy oil,and bitumen are used interchangeably herein since they may be extractedusing similar processes.

In situ is a Latin phrase for “in the place” and, in the context ofhydrocarbon recovery, refers generally to a subsurfacehydrocarbon-bearing reservoir. For example, in situ temperature meansthe temperature within the reservoir. In another usage, an in situ oilrecovery technique is one that recovers oil from a reservoir within theearth.

The term “formation” as used herein refers to a subterranean body ofrock that is distinct and continuous. The terms “reservoir” and“formation” may be used interchangeably.

In one embodiment, there is provided a method of recovering hydrocarbonsfrom an underground reservoir, the method comprising: conductingelectricity at least partially through a conductive brine within thereservoir and between two or more electrodes disposed in the reservoir,in a quantity that would, in the absence of solvent injection, causewater in the brine to vaporize in a portion of the reservoir adjacent toone or more of the electrodes, and injecting solvent into the reservoir,to limit water vaporization in the portion of the reservoir adjacent tothe one or more electrodes, by controlling a temperature of this portionof the reservoir to maintain electrical conductivity through the brine;and producing oil and solvent through one or more production wells. Thesolvent is a fluid having a bubble point temperature of between 10° C.and 100° C. at 1 atmosphere and which is at least modestly soluble inthe oil at reservoir conditions; for example, having a solubility limitof at least 5%, 20%, or 50% by mass in the hydrocarbons.

In one embodiment, conducting electricity precedes solvent injection. Inanother embodiment, solvent injection precedes conducting electricity.Similarly, either conducting electricity or injecting solvent mayproceed alone after both are effected together or they may be effectedtogether after one or the other is started alone. Therefore, wheremethods described herein refer to conducting electricity and injectingsolvent, this is not intended to limit the method to the case wheresolvent injection precedes conducting electricity.

The solvent type and solvent injection rate are chosen to control an insitu temperature and prevent excessive boiling of in situ brine, whichwould otherwise lead to excessive degradation or loss of electricalconductivity of the reservoir and hinder the ability to heat the viscousoil in situ. While it is preferable that sufficient solvent is injectedinto the reservoir to maintain the portion of the reservoir adjacent toone or more of the electrodes at a temperature below the boiling pointof water at reservoir pressure conditions, some boiling is acceptable.Therefore, reference herein is made to limiting water vaporization.There may be, for instance, localized areas or certain time periodswhere water is vaporized without reducing the electrical conductivity toan unacceptable amount.

The “conducting electricity” may be alternating current (AC) or directcurrent (DC). However, alternating current is preferred to minimizecorrosion issues. Moreover, low frequency alternating current in therange of 50-60 Hertz is preferred so as not to complicate generation anddistribution of the current. Such alternating current frequencies arecompatible with much of the standard electrical equipment used in theworld.

The electricity may be generated on site using a portion of the producedhydrocarbons or may be obtained from an offsite source. The offsitesource may be a conventional power plant, for example, fired by coal ornatural gas or may be a renewable energy source such as hydroelectric,wind, solar, or geothermal.

The instant method may be used to recover hydrocarbons, and preferablyviscous oil as defined above.

In one embodiment, depicted in FIG. 1, the method mitigateselectrothermal overheating and aids viscosity reduction by injecting ahydrocarbon solvent into the reservoir where electrothermal heating is,or will be, occurring. In some embodiments, the solvent injection canoccur through the same wells which act as, or house, electrodes. Thismay be accomplished by electrically insulating or isolating an upperportion of the well to ensure safety and avoid electrical losses tooverburden regions. Electricity may be conducted downhole, for instance,through a casing, internal tubing, or cables. FIG. 1 depicts anembodiment where solvent injection occurs through wells that also act aselectrodes. As shown in FIG. 1, a supply of solvent (102) is injectedthrough injection/electrode wells (104) passing through the overburden(106) where the electrodes are insulated (108), and into a viscous oilzone (110), where the electrodes are exposed (112). Electrical currentflow occurs between the electrodes. Solvent and mobilized oil (116) flowto the producer well (118). The source of electricity is also shown(120).

Preferably, the solvent is chosen to at least partially vaporize at atemperature below that of the water within the reservoir. In this way,in situ temperatures are limited to the solvent vaporizationtemperatures as long as the solvent does not completely boil off.

The solvent may also act to reduce viscosity of the native oil. Even ifthe solvent vaporizes, it will travel and then condense farther away andthen mix with native oil to reduce its viscosity. Non-limiting examplesof the solvent comprise C₃-C₇ (or C₅₋C₇) hydrocarbons or mixtureslargely comprising C₃-C₇ (or C₅-C₇) hydrocarbons. The injected solventhas a bubble point temperature at a pressure of 1 atmosphere between 10°C. and 100° C. For example, the bubbling point at a pressure of 1atmosphere for n-pentane is 36° C., for n-hexane is 69° C., and forn-heptane is 98° C. Solvents may comprise components other than linearalkanes; for example, cycloalkanes, aromatics, ketones, or alcohols.

The solvent injection rate and composition may be such that the solventat least partially vaporizes in situ so as to maintain at least aportion of said reservoir below the boiling point/temperature of waterat reservoir pressure conditions in a region where both solventvaporization and electric heating occur. In some embodiments, water orbrine is additionally injected into the reservoir to further control insitu temperatures and maintain or achieve a desired in situ electricalconductivity. Prior to injection, the solvent may be heated. AlthoughFIG. 1 depicts use of vertical wells, deviated or horizontal wells maylikewise be used.

Optionally, as shown in FIG. 2, the solvent is heated downhole by anelectric heating element in the wellbore. In the embodiment of FIG. 2,the method involves injecting a liquid-phase hydrocarbon solvent througha wellbore which has an electric heating element. As shown in FIG. 2,solvent is injected (202) through a well (204) passing through theoverburden (206) and into the viscous oil zone (208). The resistiveheating element (210) heats the solvent in the wellbore prior to thesolvent entering the formation. The heated solvent flow (212) and thesource of electricity (214) are also shown. In some embodiments, thesolvent is partially vaporized. Use of a hydrocarbon solvent may serveto avoid the potential buildup of inorganic scale (e.g. saltprecipitation) in or near the injection well since hydrocarbon solventsgenerally cannot hold ionic components. Depiction of the electricalcurrent flow through the reservoir is not illustrated in FIG. 2. In someembodiments, the electric heating element may be part of an electrodeused to conduct electricity through the reservoir.

In some embodiments, a backpressure maintained in the reservoir througha choke or other means, permits the solvent to be produced primarily inthe liquid phase. In other embodiments, it may be preferable to reducethe pressure sufficiently to produce some or most of the solvent as avapor phase. This may be particularly advantageous towards the end ofthe field life so to recover as much of the solvent as possible.

In certain cases, cycling injection and production may be preferredrather than continuous injection and production through dedicated wells.In such an embodiment, one or more of the injection wells may also actas production wells. Some or all of these wells may also be used aselectrodes. For example, such an embodiment may combine electrothermalheating with a cyclic solvent-dominated recovery process (CSDRP). CSDRPsare non-thermal recovery methods that use a solvent to mobilize viscousoil by cyclic injection into a subterranean viscous oil reservoirfollowed by production from the reservoir through the same well. Inparticular, the wells used for cyclic injection and production may alsobe used as electrodes. During solvent injection phases, the solventcould mitigate brine boiling. During production phases, producedsolvent-diluted bitumen and any (unmixed) reproduced solvent couldmitigate brine boiling.

CSDRP

A further discussion of a CSDRP is now provided. Where any aspect ofCSDRP, as discussed below, is inconsistent with embodiments of theinstant invention, as described above, the above description shallprevail. Of particular note is that when electrothermal heating iscombined with solvent injection, as described above, heating may accountfor greater viscosity reduction than solvation.

At the present time, solvent-dominated recovery processes (SDRPs) arerarely used to produce highly viscous oil. Highly viscous oils areproduced primarily using thermal methods in which heat, typically in theform of steam, is added to the reservoir. Cyclic solvent-dominatedrecovery processes (CSDRPs) are a subset of SDRPs. A CSDRP is typically,but not necessarily, a non-thermal recovery method that uses a solventto mobilize viscous oil by cycles of injection and production.Solvent-dominated means that the injectant comprises greater than 50% bymass of solvent or that greater than 50% of the produced oil's viscosityreduction is obtained by chemical solvation rather than by thermalmeans. One possible laboratory method for roughly comparing the relativecontribution of heat and dilution to the viscosity reduction obtained ina proposed oil recovery process is to compare the viscosity obtained bydiluting an oil sample with a solvent to the viscosity reductionobtained by heating the sample.

In a CSDRP, a viscosity-reducing solvent is injected through a well intoa subterranean viscous-oil reservoir, causing the pressure to increase.Next, the pressure is lowered and reduced-viscosity oil is produced tothe surface through the same well through which the solvent wasinjected. Multiple cycles of injection and production are used. In someinstances, a well may not undergo cycles of injection and production,but only cycles of injection or only cycles of production.

CSDRPs may be particularly attractive for thinner orlower-oil-saturation reservoirs. In such reservoirs, thermal methodsutilizing heat to reduce viscous oil viscosity may be inefficient due toexcessive heat loss to the overburden and/or underburden and/orreservoir with low oil content.

References describing specific CSDRPs include: Canadian Patent No.2,349,234 (Lim et al.); G. B. Lim et al., “Three-dimensional ScaledPhysical Modeling of Solvent Vapour Extraction of Cold Lake Bitumen”,The Journal of Canadian Petroleum Technology, 35(4), pp. 32-40, April1996; G. B. Lim et al., “Cyclic Stimulation of Cold Lake Oil Sand withSupercritical Ethane”, SPE Paper 30298, 1995; U.S. Pat. No. 3,954,141(Allen et al.); and M. Feali et al., “Feasibility Study of the CyclicVAPEX Process for Low Permeable Carbonate Systems”, InternationalPetroleum Technology Conference Paper 12833, 2008.

The family of processes within the Lim et al. references describesembodiments of a particular SDRP that is also a cyclic solvent-dominatedrecovery process (CSDRP). These processes relate to the recovery ofheavy oil and bitumen from subterranean reservoirs using cyclicinjection of a solvent in the liquid state which vaporizes uponproduction. The family of processes within the Lim et al. references maybe referred to as CSP™ processes.

During a CSDRP, a reservoir accommodates the injected solvent andnon-solvent fluid by compressing the pore fluids and, more importantlyin some embodiments, by dilating the reservoir pore space whensufficient injection pressure is applied. Pore dilation is aparticularly effective mechanism for permitting solvent to enter intoreservoirs filled with viscous oils when the reservoir comprises largelyunconsolidated sand grains. Injected solvent fingers into the oil sandsand mixes with the viscous oil to yield a reduced viscosity mixture withsignificantly higher mobility than the native viscous oil. Withoutintending to be bound by theory, the primary mixing mechanism is thoughtto be dispersive mixing, not diffusion. Preferably, injected fluid ineach cycle replaces the volume of previously recovered fluid and thenadds sufficient additional fluid to contact previously uncontactedviscous oil.

On production, the pressure is reduced and the solvent(s), non-solventinjectant, and viscous oil flow back to the same well and are producedto the surface. As the pressure in the reservoir falls, the producedfluid rate declines with time. Production of the solvent/viscous oilmixture and other injectants may be governed by any of the followingmechanisms: gas drive via solvent vaporization and native gasexsolution, compaction drive as the reservoir dilation relaxes, fluidexpansion, and gravity-driven flow. The relative importance of themechanisms depends on static properties such as solvent properties,native GOR (Gas to Oil Ratio), fluid and rock compressibilitycharacteristics, and reservoir depth, but also depends on operationalpractices such as solvent injection volume, producing pressure, andviscous oil recovery to-date, among other factors.

Table 1 outlines the operating ranges for CSDRPs of some embodiments.The present invention is not intended to be limited by such operatingranges.

TABLE 1 Operating Ranges for a CSDRP. Parameter Broader EmbodimentNarrower Embodiment Injectant volume Fill-up estimated pattern poreInject, beyond a pressure volume plus 2-15% of threshold, 2-15% (or3-8%) of estimated pattern pore volume; estimated pore volume. orinject, beyond a pressure threshold, for a period of time (for exampleweeks to months); or inject, beyond a pressure threshold, 2-15% ofestimated pore volume. Injectant Main solvent (>50 mass %) C₂-C₅. Mainsolvent (>50 mass %) is composition, Alternatively, wells may be propane(C₃). main subjected to compositions other than main solvents to improvewell pattern performance (i.e. CO₂ flooding of a mature operation oraltering in situ stress of reservoir). Injectant Additional injectantsmay Only diluent, and only when composition, include CO₂ (up to about30%), needed to achieve adequate additive C₃₊, viscosifiers (for exampleinjection pressure. diesel, viscous oil, bitumen, diluent), ketones,alcohols, sulphur dioxide, hydrate inhibitors, and steam. Injectantphase & Solvent injected such that at Solvent injected as a liquid, andInjection the end of injection, greater most solvent injected just underpressure than 25% by mass of the fracture pressure and above solventexists as a liquid in the dilation pressure, reservoir, with noconstraint as P_(fracture) > P_(injection) > P_(dilation) > to whethermost solvent is P_(vapor)P. injected above or below dilation pressure orfracture pressure. Injectant Enough heat to prevent Enough heat toprevent hydrates temperature hydrates and locally enhance with a safetymargin, wellbore inflow consistent with T_(hydrate) + 5° C. toT_(hydrate) + Boberg-Lantz mode 50° C. Injection rate 0.1 to 10 m³/dayper meter of 0.2 to 2 m³/day per meter of completed well length (ratecompleted well length (rate expressed as volumes of liquid expressed asvolumes of liquid solvent at reservoir conditions). solvent at reservoirconditions). Rates may also be designed to allow for limited orcontrolled fracture extent, at fracture pressure or desired solventconformance depending on reservoir properties. Threshold Any pressureabove initial A pressure between 90% and pressure reservoir pressure.100% of fracture pressure. (pressure at which solvent continues to beinjected for either a period of time or in a volume amount) Well lengthAs long of a horizontal well as 500 m-1500 m (commercial well). canpractically be drilled; or the entire pay thickness for vertical wells.Well Horizontal wells parallel to Horizontal wells parallel to eachconfiguration each other, separated by some other, separated by someregular regular spacing of 60-600 m; spacing of 60-320 m. also verticalwells, high angle slant wells & multi-lateral wells. Also infillinjection and/or production wells (of any type above) targeting bypassedhydrocarbon from surveillance of pattern performance. Well orientationOrientated in any direction. Horizontal wells orientated perpendicularto (or with less than 30 degrees of variation) the direction of maximumhorizontal in situ stress. Minimum Generally, the range of the A lowpressure below the vapor producing MPP should be, on the low pressure ofthe main solvent, pressure (MPP) end, a pressure significantly ensuringvaporization, or, in the below the vapor pressure, limited vaporizationscheme, a ensuring vaporization; and, on high pressure above the vaporthe high-end, a high pressure pressure. At 500 m depth with near thenative reservoir pure propane, 0.5 MPa (low)-1.5 MPa pressure. Forexample, (high), values that bound the perhaps 0.1 MPa-5 MPa, 800 kPavapor pressure of depending on depth and mode propane. of operation(all-liquid or limited vaporization). Oil rate Switch to injection whenrate Switch when the instantaneous oil equals 2 to 50% of the max ratedeclines below the calendar rate obtained during the cycle. day oil rate(CDOR) (for example Alternatively, switch when total oil/total cyclelength). Likely absolute rate equals a pre-set most economically optimalwhen value. Alternatively, well is the oil rate is at about 0.8 × unableto sustain hydrocarbon CDOR. Alternatively, switch to flow (continuousor injection when rate equals 20-40% intermittent) by primary of the maxrate obtained during production against the cycle. backpressure ofgathering system or well is “pumped off” unable to sustain flow fromartificial lift. Alternatively, well is out-of-synch with adjacent wellcycles. Gas rate Switch to injection when gas Switch to injection whengas rate rate exceeds the capacity of exceeds the capacity of the thepumping or gas venting pumping or gas venting system. system. Well isunable to During production, an optimal sustain hydrocarbon flowstrategy is one that limits gas (continuous or intermittent) byproduction and maximizes liquid primary production against from ahorizontal well. backpressure of gathering system with/or withoutcompression facilities. Oil to Solvent Begin another cycle if the Beginanother cycle if the OISR of Ratio OISR of the just completed the justcompleted cycle is above cycle is above 0.15 or 0.3. economic threshold.Abandonment Atmospheric or a value at For propane and a depth of 500 m,pressure which all of the solvent is about 340 kPa, the likely lowest(pressure at vaporized. obtainable bottomhole pressure at which well isthe operating depth and well produced after below the value at which allof the CSDRP cycles propane is vaporized. are completed)

In Table 1, embodiments may be formed by combining two or moreparameters and, for brevity and clarity, each of these combinations willnot be individually listed.

In the context of this specification, diluent means a liquid compoundthat can be used to dilute the solvent and can be used to manipulate theviscosity of any resulting solvent-bitumen mixture. By such manipulationof the viscosity of the solvent-bitumen (and diluent) mixture, theinvasion, mobility, and distribution of solvent in the reservoir can becontrolled so as to increase viscous oil production.

The diluent is typically a viscous hydrocarbon liquid, especially a C₄to C₂₀ hydrocarbon, or mixture thereof, is commonly locally produced andis typically used to thin bitumen to pipeline specifications. Pentane,hexane, and heptane are commonly components of such diluents. Bitumenitself can be used to modify the viscosity of the injected fluid, oftenin conjunction with ethane solvent.

In certain embodiments, the diluent may have an average initial boilingpoint close to the boiling point of pentane (36° C.) or hexane (69° C.)though the average boiling point (defined further below) may change withreuse as the mix changes (some of the solvent originating among therecovered viscous oil fractions). Preferably, more than 50% by weight ofthe diluent has an average boiling point lower than the boiling point ofdecane (174° C.). More preferably, more than 75% by weight, especiallymore than 80% by weight, and particularly more than 90% by weight of thediluent, has an average boiling point between the boiling point ofpentane and the boiling point of decane. In further preferredembodiments, the diluent has an average boiling point close to theboiling point of hexane (69° C.) or heptane (98° C.), or even water(100° C.).

In additional embodiments, more than 50% by weight of the diluent(particularly more than 75% or 80% by weight and especially more than90% by weight) has a boiling point between the boiling points of pentaneand decane. In other embodiments, more than 50% by weight of the diluenthas a boiling point between the boiling points of hexane (69° C.) andnonane (151° C.), particularly between the boiling points of heptane(98° C.) and octane (126° C.).

By average boiling point of the diluent, we mean the boiling point ofthe diluent remaining after half (by weight) of a starting amount ofdiluent has been boiled off as defined by ASTM D 2887 (1997), forexample. The average boiling point can be determined by gaschromatographic methods or more tediously by distillation. Boilingpoints are defined as the boiling points at atmospheric pressure.

In the preceding description, for purposes of explanation, numerousdetails are set forth in order to provide a thorough understanding ofthe embodiments of the invention. However, it will be apparent to oneskilled in the art that these specific details are not required in orderto practice the invention.

The above-described embodiments of the invention are intended to beexamples only. Alterations, modifications and variations can be effectedto the particular embodiments by those of skill in the art withoutdeparting from the scope of the invention, which is defined solely bythe claims appended hereto.

1. A method of recovering hydrocarbons from an underground reservoir,the method comprising: (a) conducting electricity at least partiallythrough a conductive brine within the reservoir between two or moreelectrodes disposed in the reservoir; (b) injecting solvent into thereservoir at least partially in a liquid phase and where the solvent hasa bubble point temperature between 10° C. and 100° C. at a pressure of 1atm.; (c) heating a portion of the reservoir through said conduction ofelectricity to vaporize at least a portion of the injected solvent; and(d) producing hydrocarbons through one or more wells.
 2. The method ofclaim 1 wherein sufficient solvent is injected into the reservoir andproximate to one or more of the two or more electrodes to maintain theportion of the reservoir at a temperature below the boiling pointtemperature of water at reservoir pressure conditions.
 3. The method ofclaim 1 wherein the hydrocarbons are a viscous oil having an in situviscosity greater than 10 cP at initial reservoir conditions.
 4. Themethod of claim 1 wherein the portion of the reservoir is adjacent to atleast one of the two or more electrodes.
 5. The method of claim 1further comprising injecting a conductive brine into the reservoir tofurther control reservoir in situ temperature or to maintain or achievein situ conductivity.
 6. The method of claim 1 wherein the solventcomprises propane, butane, pentane, hexane, or heptane, or a combinationthereof.
 7. The method of claim 1 further comprising heating the solventabove ground prior to injection.
 8. The method of claim 1 furthercomprising heating the solvent beneath ground prior to injection intothe reservoir.
 9. The method of claim 8 wherein the solvent heating iseffected by a subsurface electric heating element.
 10. The method ofclaim 1 wherein the solvent is produced through one or more wells and isat least partially produced as a vapor.
 11. The method of claim 1wherein one or more wells used for solvent injection are also used as,or houses, one or more of the two or more electrodes.
 12. The method ofclaim 1 wherein one or more of the one or more wells used for productionis also used as, or houses, one or more of the two or more electrodes.13. The method of claim 1 wherein the solvent is injected through atleast two injection wells which act as, or house, the two or moreelectrodes, respectively.
 14. The method of claim 1 wherein the solventhas a bubble point temperature between 35° C. and 99° C. at a pressureof 1 atm.
 15. The method of claim 1 wherein the solvent has a solubilitylimit at reservoir conditions of at least 5% by mass in the hydrocarbonsin the underground reservoir.
 16. The method of claim 1 wherein thesolvent has a solubility limit at reservoir conditions of at least 20%by mass in the hydrocarbons in the underground reservoir.
 17. The methodof claim 1 wherein the solvent has a solubility limit at reservoirconditions of at least 50% by mass in the hydrocarbons in theunderground reservoir.
 18. The method of claim 1 wherein at least 25mass % of the solvent enters the reservoir as a liquid.
 19. The methodof claim 1 wherein at least 50 mass % of the solvent enters thereservoir as a liquid.
 20. The method of claim 1 wherein the solventcomprises greater than 50 mass % of components comprising propane,butane, or pentane.
 21. The method of claim 1 wherein the solventcomprises greater than 50 mass % propane.
 22. The method of claim 1wherein the solvent comprises greater than 70 mass % propane.
 23. Themethod of claim 1 wherein cycles of solvent injection and solvent andhydrocarbon production occur through the one or more wells and where theone or more wells also act as or house one or more of the two or moreelectrodes.